At the outset of a drilling operation, drillers typically establish a drilling plan that includes a target location and a drilling path to the target location. Once drilling commences, the bottom hole assembly (BHA) may be directed or “steered” from a vertical drilling path in any number of directions, to follow the proposed drilling plan. For example, to recover an underground hydrocarbon deposit, a drilling plan might include a vertical bore to a point above the reservoir, then a directional or horizontal bore that penetrates the deposit. The operator may then follow the plan by steering the BHA through the vertical and horizontal aspects in accordance with the plan.
In slide drilling implementations, such directional drilling requires accurate orientation of a bent housing of the downhole motor. The bent housing is set on surface to a predetermined angle of bend. The high side of this bend is referred to as the toolface of the BHA. In such slide drilling implementations, rotating the drill string changes the orientation of the bent housing and the BHA, and thus the toolface. To effectively steer the assembly, the operator must first determine the current toolface orientation, such as via measurement-while-drilling (MWD) apparatus. Thereafter, if the drilling direction needs adjustment, the operator must rotate the drill string to change the toolface orientation. In rotary steerable system implementations, the operator still must determine the current toolface orientation.
During drilling, a “survey” identifying locational and directional data of a BHA in a well is obtained at various intervals. Each survey yields a measurement of the inclination angle from vertical and azimuth (or compass heading) of the survey probe in a well (typically 40-50 feet behind the total depth at the time of measurement). In directional wellbores, particularly, the position of the wellbore must be known with reasonable accuracy to ensure the correct steering of the wellbore path. The measurements themselves include inclination from vertical and the azimuth of the well bore. In addition to the toolface data, and inclination, and azimuth, the data obtained during each survey may also include hole depth data, pipe rotational data, hook load data, delta pressure data (across the downhole drilling motor), and modeled dogleg data, for example.
These measurements may be taken at discrete points in the well, and the approximate path of the wellbore may be computed from the data obtained at these discrete points. Conventionally, a standard survey is conducted at each drill pipe connection, at approximately every 90 feet, to obtain an accurate measurement of inclination and azimuth for the new survey position.
When deviation from the planned drilling path occurs, drillers must consider the information available to them and then direct the drill back to the original path. This typically requires the operator to manipulate the drawworks brake and rotate the rotary table or top drive quill to find the precise combinations of hook load, mud motor differential pressure, and drill string torque, to properly position the toolface. This can be difficult, time consuming, and complex. Each adjustment has different effects on the toolface orientation, and each must be considered in combination with other drilling requirements to drill the hole. Thus, reorienting the toolface in a bore is very complex, labor intensive, and often inaccurate. Furthermore, information required to steer the drilling BHA is generally transmitted to the operator in a textual format in conventional systems. An operator must consider the implications of this textual information, formulate a visual mental impression of the overall orientation of the drilling BHA, and try to formulate a steering plan based on this mental impression, before steering the system. A more efficient, reliable, and intuitive method for steering a BHA is needed.